Deep shale has gradually become a focus point for unconventional natural gas exploration and development in China and even the world. The key to deep shale development is the fracability evaluation of a reservoir; conventional evaluation methods cannot provide accurate evaluations of deep shale fracability under high confining pressures. In this study, experimental methods are used to obtain the mechanical parameters, mineral composition, and stress–strain characteristics of shale. The fracture complexity coefficient based on the fractal dimension and fracture angle is defined by analyzing the fracture morphology of shale samples. Using the rock fracturing complexity as an index, the weight coefficients of different factors for the shale fracture morphology are obtained, thus establishing a new evaluation model for the deep shale brittleness index. The results show that the Young's modulus, dilatancy angle, and peak strain are the main factors affecting the complexity of shale fractures. The gray correlation theory is used to calculate the weights of various factors in the model. The weight coefficients of the Young's modulus, dilatancy angle, and peak strain on the rock brittleness index are 0.262, 0.353, and 0.385, respectively. Based on this, a novel method for evaluating the fracability of deep shale using the brittleness index is proposed. The fracability index of the horizontal section of the deep shale gas well in this area was calculated, and the location of the fracturing perforation cluster was optimized accordingly. This technology has been successfully applied in more than 10 deep shale gas wells in the southern Sichuan Basin, effectively reducing the fracturing pressure by 5–10 MPa, increasing the average daily production of a single well by 15.3 × 10⁴ m³. This paper proposes a novel fracability evaluation method for deep shale based on the brittleness index, which provides a reference for optimizing deep shale fracturing design.

Based on computational fluid dynamics (CFD) and discrete element method (DEM), the factors affecting proppant transport law in hydraulic fracture and natural fracture are analyzed. The results indicated that the smaller the angle between hydraulic fracture and natural fracture, and the larger the width of natural fracture, the more proppants enter the natural fracture. As the viscosity of the fracturing fluid increases, the length of the “no proppant zone” in fracture is longer, and the proppant particles can be transported to a farther position. Proppant will quickly reach the fracture tip and be screened out under too high injection rate.